Although nano SiO2 exhibits excellent application potential in the field of oil and gas exploration and development, such as drilling fluid, enhanced oil/gas recovery, etc., it is prone to agglomeration and loses its effectiveness due to the action of cations in saline environments of oil and gas reservoirs. Therefore, it is crucial to study the mechanism of the change in energy between nano SiO2 and cations for its industrial application. In this paper, the effect of cations (Na+, K+, Ca2+, and Mg2+) on the surface energy of nano SiO2 particles is investigated from the perspective of molecular motion and electronic change by density functional theory. The results are as follows: Due to the electrostatic interactions, cations can migrate towards the surface of nano SiO2 particles. During the migration process, monovalent cations are almost unaffected by water molecules, and they can be directly adsorbed on the surface by nano SiO2 particles. However, when divalent cations migrate from a distance to the surface of nano SiO2 particles, they can combine with water molecules to create an energy barrier, which can prevent them from moving forward. When divalent cations break through the energy barrier, the electronic kinetic energy between them and nano SiO2 particles changes more strongly, and the electrons carried by them are more likely to break through the edge of the atomic nucleus and undergo charge exchange with nano SiO2 particles. The change in interaction energy is more intense, which can further disrupt the configuration stability of nano SiO2. The interaction energy between cations and nano SiO2 particles mainly comes from electrostatic energy, followed by Van der Waals energy. From the degree of influence of four cations on nano SiO2 particles, the order from small to large is as follows: K+ < Na+ < Mg2+ < Ca2+. The research results can provide a theoretical understanding of the interaction between nano SiO2 particles and cations during the application of nano SiO2 in the field of oil and gas exploration and development.

The solubility of CO2-N-2 gas mixtures in water is important for CO2/flue gas sequestration in aquifer. Having precise thermodynamic measurements as well as credible prediction models to utilize in innovative carbon capture and storage (CCS) systems is critical. In this study, two simple-to-use white-box models, including Gene Expression Programming (GEP) and Group Method of Data Handling (GMDH) models, have been developed using 289 experimental data to predict the solubility of CO2-N-2 gas mixtures in aqueous solutions. Four tuned equations of state (EOSs), namely Peng-Robinson (PR), Soave-Redlich-Kwong (SRK), Zudkevitch-Joffe (ZJ), and Redlich-Kwong (RK), as well as the outcomes of the GEP and GMDH, were compared. The results show that the tuned EOSs perform much better than the untuned EOSs. The results show that the GMDH model has the best predictive performance such that the obtained values of root mean square error (RMSE) and coefficient of determination (R-2) are 0.000564 and 0.9792, respectively. It should be noted that the GEP model also has acceptable accuracy, with RMSE and R-2 values of 0.00081 and 0.9465, respectively. The SRK model obtained the best outcomes among the EOSs for the solubility of the CO2-N-2 gas mixture in aqueous solution, with RMSE and R-2 values of 0.00128 and 0.9561, respectively. The results also show that the solubility of CO2 in aqueous solutions is much higher than N-2, and increasing the pressure increases the solubility of CO2 and N-2 in aqueous solutions, while increasing the CO2 content increases and decreases the solubility of CO2 and N-2, respectively. Group error analysis also shows that the developed models have less error in low values of temperature, pressure, and CO2 content. Finally, in order to validate the results of the GMDH and GEP models, the leverage technique has been utilized, which illustrated that 95% of the data are in the valid region, thus, the developed models are statistically reliable. The findings of this study can help for better understanding the solubility process of CO2 and N-2 in water to overcome thermodynamic and environmental challenge

The technology of radial-well-assisted hydraulic fracturing is applied in the stimulation of low-permeability hydrocarbon reservoirs where commercial production cannot be achieved by the conventional fracturing method. Here, a study on the reservoir stimulation effect and the fracture propagation pattern of radial-well-assisted deflagration fracturing was carried out. Based on smooth particle hydrodynamics (SPH), rock mechanics theory, and finite element theory, a numerical model of radial-well-assisted deflagration fracturing was established by integrating the JWL state equation. Research on the effects of the deflagration position, radial well azimuth and horizontal principal stress difference on the fracture propagation was carried out. The results show that the deflagration position, radial well azimuth and horizontal principal stress difference have significant effects on the fracture area in deflagration fracturing. The closer distance from the deflagration position is, the larger the radial well azimuth and the smaller the horizontal stress difference are, leading to a larger fracture area, which is conducive to reservoir stimulation. During fracturing, both shear fractures and tensile fractures are formed. The formation and conversion of shear fractures and tensile fractures are related to the deflagration position, radial well azimuth, horizontal principal stress difference, etc.

CO2 flooding is one of the effective methods to improve oil and gas recovery. The property of CO2 varies under supercritical, gaseous, and liquid phases. The exterior and stability in the different phases of CO2 foam also vary. Using a high-temperature and high-pressure foam instrument, the gaseous, liquid, and supercritical CO2 foam performance was studied. Experimental results show the exterior formation of supercritical CO2 foam between gaseous and liquid CO2. The CO2 stabilizes when the pressure increases and the temperature decreases, but pressure has a more significant impact than temperature. The CO2 foam volume and half-time will decrease as the temperature rises. Meanwhile, the foaming ability and foam stability of CO2 bubbles are significantly increased as the pressure rises, especially in the supercritical state. In the foam block test, the supercritical CO2 foam resistance factor is higher than that in the gaseous and liquid CO2 foam systems.

The chemotactic properties of an oil-degrading Pseudomonas aeruginosa strain 6-1B, isolated from Daqing Oilfield, China, have been investigated. The strain 6-1B could grow well in crude oil with a specific rhamnolipid biosurfactant production. Furthermore, it exhibits chemotaxis toward various substrates, including glycine, glycerol, glucose, and sucrose. Compared with another oil-degrading strain, T7-2, the strain 6-1B presented a better chemotactic response towards crude oil and its vital component, n -alkenes. Based on the observed distribution of the strain 6-1B cells around the oil droplet in the chemotactic assays, the potential chemotaxis process of bacteria toward crude oil could be summarized in the following steps: searching, moving and consuming.

The flow pattern is unique in a certain range of pore size divided by the Knudsen number. In order to characterize permeability of nano-pore in shale gas reservoir more accurately, and solve the issue of apparent permeability calculation, the formulas of nano-pore permeability are put forward considering the influence of adsorption gas and pore size distribution, taking the chang7 shale gas reservoir of of Ordos Basin as an instance. After the calculated results were compared and analyzed, the conclusions are obtained as follows: (1) Pore size is the main factor to determine the flow pattern; (2) There are three main flow pattern in the shale reservoirs nano-pore, slip flow, Fick diffusion and transition diffusion, meanwhile Darcy percolation and Knudsen diffusion do not exist; (3) Flow pattern has great influence on apparent permeability and adsorption has a greater impact in a high pressure condition (greater than 20 MPa).